Applying treatment fluid to a subterranean rock matrix

ABSTRACT

The present disclosure relates to applying treatment fluid to a rock matrix in a subterranean formation. An injection fluid is received in a wellbore in a subterranean formation. The subterranean formation includes a rock matrix about the wellbore. Shear bands are induced in the rock matrix by communicating the injection fluid from the wellbore into the rock matrix. A chemical treatment fluid is communicated through the shear bands into the matrix. The chemical treatment is conducted from the wellbore primarily by a portion of the rock matrix that forms a wall of the wellbore, primarily by a subset of the shear bands that intersect the wall of the wellbore, or primarily by a combination of them. In some instances, the shear bands may improve uniformity or efficiency of the chemical treatment.

BACKGROUND

The present disclosure relates to applying treatment fluid to a rock matrix in a subterranean formation. Chemical treatments are often applied to subterranean formations by injecting the chemical treatment fluid through a wellbore in the formation. For example, conventional chemical treatments include acid stimulation treatments, scale inhibitor treatments, heat treatments, consolidation treatments, and others. Such chemical treatments are used to enhance resource production from the formation, to strengthen the structure of the formation, or to otherwise condition the formation for various types of activities.

SUMMARY

The present disclosure relates to applying treatment fluid to a rock matrix in a subterranean formation. In a general aspect, discontinuities are formed in the rock matrix, and the discontinuities conduct the treatment fluid in the rock matrix.

In one aspect, a method of performing a chemical treatment of a rock matrix includes receiving an injection fluid in a wellbore in a subterranean formation. The subterranean formation includes a rock matrix about the wellbore. Shear bands are induced in the rock matrix by communicating the injection fluid from the wellbore into the rock matrix. A chemical treatment fluid is communicated through the shear bands into the matrix. The injection fluid and the chemical treatment fluid may be the same fluid. The chemical treatment fluid is conducted from the wellbore primarily by a portion of the rock matrix that forms a wall of the wellbore, primarily by a subset of the shear bands that intersect the wall of the wellbore, or primarily by a combination of them. The rock matrix may be exposed to the wellbore either directly as with an open hole exposure to the wellbore or via fluid transmitting penetrations of a (tubular) lining of the wellbore.

Implementations of these and other aspects may include one or more of the following features. A leak-off rate of the injection fluid increases the pore pressure of the rock matrix surrounding the wellbore. Increased pore pressure causes dilatancy, lower effective stress, reduced stress anisotropy, and lower consolidation strength in the rock matrix surrounding the well bore. A leak-off rate of the injection fluid in the rock matrix prevents initiation of a dominant fracture at the wellbore wall. The injection fluid is the chemical treatment fluid. Or, the injection fluid and the chemical treatment fluid may be two different fluids. The chemical treatment fluid is received in the wellbore and communicated through the shear bands after the injection fluid is communicated into the rock matrix. The shear bands are induced substantially uniformly in the rock matrix about a longitudinal section of the wellbore. The rock matrix includes a soft rock formation having a Young's Modulus less than two million. The chemical treatment includes an acid stimulation treatment, a solvent treatment, a formation stabilizing treatment, a consolidation treatment, or a scale inhibitor treatment.

In one aspect, a chemical treatment method for treating a rock matrix about a subterranean wellbore includes communicating a first fluid from the wellbore into an interval of the rock matrix about the wellbore. The first fluid is communicated into the interval under a condition that forms shear bands in the interval. A chemical treatment fluid is communicated uniformly into the interval. The chemical treatment fluid is conducted from the wellbore primarily by a portion of the rock matrix that forms a wall of the wellbore, primarily by a subset of the shear bands that intersect the wall of the wellbore, or primarily by a combination of them.

Implementations of these and other aspects may include one or more of the following features. The condition that forms shear bands in the interval can be a pressure condition, an injection rate condition, or both. The chemical treatment fluid is communicated to the wall of the wellbore by perforations through a wellbore liner. Inducing the shear bands in the rock matrix effectively increases the bulk permeability of the rock matrix near the wellbore. The first fluid is a thin injection fluid that contains substantially no solids and forms substantially no filter cakes. The interval is a first interval. A proppant-laden fluid may be injected into the first interval. A diverter material may be used to limit injection into the first interval. The first fluid is communicated into a second, different interval of the rock matrix at a pressure and rate that forms shear bands in the second interval. The chemical treatment fluid is conducted into the second interval through the shear bands in the second interval.

In one aspect, a chemical treatment system for applying a chemical treatment to a rock matrix includes a conduit system in a wellbore. The chemical treatment system includes a fluid supply system in communication with the conduit system. The fluid supply system includes a thin injection fluid and a chemical treatment fluid. The chemical treatment system includes a port system in fluid communication with the conduit system. The port system is operable to receive the injection fluid and the chemical treatment fluid from the conduit system. The port system is operable to communicate the injection fluid into the rock matrix at an injection pressure and rate that induces shear bands in the rock matrix about the wellbore. The port system is operable to communicate the chemical treatment fluid into the rock matrix primarily through a portion of the rock matrix that forms a wall of the wellbore, primarily through a subset of the shear bands that intersect the wall of the wellbore, or primarily through a combination of them.

Implementations of these and other aspects may include one or more of the following features. The fluid supply system resides at a well system surface. The fluid supply system includes a single fluid composition that includes both the injection fluid and the chemical treatment fluid. The fluid supply system includes a first fluid composition that is the thin injection fluid, and the fluid supply system includes a second, different fluid composition that is the chemical treatment fluid. The conduit system includes an injection tubular or a production string, and the port system includes one or more inflow control devices. The conduit system includes a wellbore casing, and the port system includes one or more perforations in the wellbore casing. The chemical treatment fluid is communicated to the wall of the wellbore by perforations through a wellbore liner.

The details of one or more implementations of the subject matter described in this specification are set forth in the accompanying drawings and the description below. Other features, aspects, and advantages of the subject matter will become apparent from the description, the drawings, and the claims.

DESCRIPTION OF DRAWINGS

FIG. 1 is a diagram of an example well system for applying a chemical treatment to a subterranean formation.

FIG. 1A is a diagram of the example well system for applying a chemical treatment to a subterranean formation showing open hole exposure of a rock matrix.

FIG. 2A is a diagram of an example rock matrix that includes shear bands.

FIG. 2B is a diagram of an example rock matrix that includes bi-wing fractures.

FIG. 2C is a diagram of an example rock matrix that includes radial shear bands.

FIG. 3 is a diagram of an example well system for applying a chemical treatment to a subterranean formation.

FIGS. 4A, 4B, and 4C are a diagrams of an example well system for applying a chemical treatment to multiple intervals of a subterranean formation.

FIG. 5 is a flow chart for an example process for applying a chemical treatment to a subterranean formation.

Like reference symbols in the various drawings indicate like elements.

DETAILED DESCRIPTION

FIG. 1 is a diagram of an example well system 100 for applying a chemical treatment to a subterranean formation 101. The well system 100 includes an injection system 110 that applies a treatment fluid 108 to a rock matrix 106 of the subterranean formation 101. The injection system 110 includes control trucks 112, pump trucks 114, a wellbore 103, a work string 104 and other equipment. In the example shown in FIG. 1, the pump trucks 114, the control trucks 112 and other related equipment are above the surface 102, and the wellbore 103, the work string 104, and other equipment are beneath the surface 102. An injection system can be configured as shown in FIG. 1 or in a different manner, and may include additional or different features as appropriate. The injection system may be deployed via skid equipment, marine vessel deployed or may be comprised of sub-sea deployed equipment.

The subterranean formation 101 includes the rock matrix 106 about the wellbore 103. In some implementations, a chemical treatment is applied substantially uniformly to the rock matrix 106. For example, the chemical treatment can be applied by injecting a treatment fluid into the rock matrix 106 through the wellbore 103. The treatment fluid can be injected into a soft rock formation about the wellbore 103 to uniformly permeate an interval of the formation and form shear discontinuities in the rock. The treatment fluid can be a thin, low viscosity fluid that has a high leak-off rate in the rock. The treatment fluid can be injected at or above a fracture pressure and rate or rock matrix parting pressure and rate so as to induce shear bands without forming a dominant fracture (e.g., a bi-wing fracture) at the wellbore wall. The shear bands can conduct the chemical treatment fluid from the wellbore into the rock matrix, and in some cases, thereby achieve more uniform placement of the chemical treatment fluid in the rock matrix.

The formation can include a soft, highly plastic rock that does not have a dominant stress contrast at the wellbore. The mechanical properties of the rock along with the fluid properties of the chemical treatment fluid may induce shear bands in the rock formation about the wellbore without initiating or propagating a dominant fracture at the wellbore wall on injection of the treatment. As such, the injection can from a complex network of interconnected shear bands in the rock matrix, which may act as a conduit for communicating treatment fluids uniformly throughout the rock matrix adjacent to the wellbore. For example, by creating shear bands in the rock matrix, the chemical treatment can, in some cases, more uniformly permeate the near wellbore rock matrix.

In some instances, fluids containing adjunct materials (e.g., sand, gravel, proppant material, diverter material, permeability modifier, etc.) may also be injected, for example, in addition to the thin injection fluid that forms the shear bands. The particulate or diverter materials can be placed, for example, at an interface between the wellbore and the rock matrix to modify the flow path of the treatment fluid. Such diverter material can be used to enhance the uniform placement of the treatment fluid, for example, in other intervals of the rock formation.

The wellbore 103 shown in FIG. 1 includes vertical and horizontal sections, and the treatment fluid 108 is applied to the rock matrix 106 surrounding the horizontal portion of the wellbore. Generally, a wellbore may include horizontal, vertical, slant, curved, and other types of wellbore geometries and orientations, and the chemical treatment may generally be applied to a rock matrix surrounding any portion of a wellbore. The wellbore 103 can include a casing that is cemented or otherwise secured to the wellbore wall. The wellbore 103 can be uncased or include uncased sections. Perforations can be formed in the casing to allow treatment fluids and/or other materials to flow into the rock matrix 106. Perforations can be formed using shape charges, a perforating gun, and/or other tools.

The pump trucks 114 may include mobile vehicles, immobile installations, skids, hoses, tubes, fluid tanks or reservoirs, pumps, valves, and/or other suitable structures and equipment. The pump trucks 114 supply treatment fluid 108 from a fluid supply 118. The pump trucks can communicate with the control trucks 112, for example, by a communication link 113. The fluid supply system can include a tank, reservoir, connections to external fluid supplies, and/or other suitable structures and equipment. The pump trucks 114 are coupled to the work string 104 to communicate the treatment fluid 108 into the wellbore 103.

The working string 104 may include coiled tubing, sectioned pipe, and/or other structures that communicate fluid through the wellbore 103. The working string 104 can include flow control devices, bypass valves, ports, and or other tools or well devices that control a flow of fluid from the interior of the working string 104 into the rock matrix 106. For example, the working string 104 may include ports that abut the wellbore wall to communicate the treatment fluid 108 directly into the rock matrix 106, and/or the working string 104 may include ports that are spaced apart from the wellbore wall to communicate the treatment fluid 108 into an annulus in the wellbore between the working string 104 and the wellbore wall. Although FIG. 1 shows the horizontal section of the working string 104 represents an inner tubular structure of the well system 100, in some embodiments, such inner tubular structure may be absent.

The control trucks 112 can include mobile vehicles, immobile installations, and/or other suitable structures. The control trucks 112 control and/or monitor the injection treatment. For example, the control trucks 112 may include communication links that allows the control trucks 112 to communicate with tools, sensors, and/or other devices installed in the wellbore 103. The control trucks 112 may include communication links that allow the control trucks 112 to communicate with the pump trucks 114 and/or other systems at the surface 102. The control trucks 112 may include an injection control system that controls the flow of the treatment fluid 108 into the rock matrix 106. For example, the control trucks 112 may monitor and/or control the density, volume, flow rate, flow pressure, location, and/or other properties of the treatment fluid 108 injected into the rock matrix 106.

The injection system 110 may also include surface and down-hole sensors (not shown) to measure pressure, rate, temperature and/or other parameters of treatment. The injection system 110 may include pump controls and/or other types of controls for starting, stopping and/or otherwise controlling pumping as well as controls for selecting and/or otherwise controlling fluids pumped during the injection treatment. An injection control system (e.g. in the control trucks 112) may communicate with such equipment to monitor and control the injection treatment.

Applying the chemical treatment includes injecting the chemical treatment fluid 108 into the rock matrix 106 to treat the rock matrix 106. In some cases, it is desirable to treat the rock matrix uniformly around (e.g., 360 degrees) the wellbore and uniformly along longitudinal section of the wellbore. In some implementations of the well system 100, a chemical treatment is applied more uniformly by injecting the chemical treatment fluid 108 at a pressure that forms shear bands in the rock matrix and by using the shear bands to conduct the fluid into the rock matrix. For example, the shear bands may be formed by injecting the chemical treatment fluid above a fracture pressure and by using a low efficiency fluid that does not open a dominant fracture at the wellbore wall.

Example chemical treatments include acid stimulation treatments, formation stabilization treatments, consolidation treatments, scale inhibitor treatments, treatments that remove buildup of paraffin, asphaltene, or another substance from the rock material, heat transfer treatments, water flood treatments, and others. Acid stimulation treatments apply an acidic fluid to a rock formation to improve the production or injection flow capacity, for example, by dissolving material plugging the pores or by enlarging the pore spaces. Formation stabilization treatments apply treatment fluid to a subterranean zone to reduce movement of the matrix formation grains and fine particles during operation of the well including production or injection operations. Consolidation treatments apply treatment fluid to a subterranean zone to control production of sand and other undesirable substances from the zone. For example, a consolidation treatment can be applied to a weak sandstone formation to chemically bind the grains of sand while maintaining sufficient permeability to achieve viable production rates. Scale inhibitor treatments apply treatment fluid to control or prevent scale deposition in the production conduit or completion system. Heat transfer treatments apply heated fluids to a subterranean zone to affect material properties of the zone, for example, to achieve a desired flow rate. Waterflood treatments inject fluids to act as a secondary recovery treatment, for example, to displace residual hydrocarbons.

In one aspect of operation, the injection system 110 applies a chemical treatment to the rock matrix 106. The control truck 112 controls and monitors the pump truck 114 which pumps the treatment fluid 108 from the fluid supply system 118 through the work string 104, into the wellbore 103, and subsequently into the rock matrix 106. The treatment fluid 108 can be injected at a pressure that induces shear bands in the rock matrix 106. The treatment fluid 108 can be injected in a manner that prevents a dominant fracture from forming at the interior wall of the wellbore 103. For example, the treatment fluid 108 can have a sufficiently high leak-off rate in the rock matrix 106 to prevent formation of a dominant fracture. As such, the shear bands formed by the treatment fluid 108 conduct the injection fluid into the rock matrix 106. In some cases, a portion of rock matrix 106 that forms the interior wall of the wellbore acts as the primary fluid conductor that communicates fluid from the interior of the wellbore into the rock matrix 106. In some cases, shear bands formed by the treatment fluid 108 intersect the interior wall of the wellbore, and the shear bands intersecting the interior wall act as the primary fluid conductor that communicates fluid from the interior of the wellbore into the rock matrix 106. In some cases, both the shear bands and the rock matrix at the wellbore wall act as the primary conductor.

FIG. 1A is a diagram of the example well system for applying a chemical treatment to a subterranean formation showing open hole exposure of rock matrix. Elements in FIG. 1A are similar to those of FIG. 1, except that FIG. 1A shows open hole exposure of the rock matrix 106 between the horizontal section of the wellbore 103 and the rock matrix 106.

FIG. 2A is a diagram 200 a of an example rock matrix 202 a that includes shear bands 203. The diagram 200 a is viewed at a cross-section, with a wellbore 201 a at the center of the diagram. The shear bands 203 can be induced by pumping highly permeable fluids through the wellbore 201 a and into the rock matrix 202 a at a fluid pressure that induces discontinuities in the rock matrix 202 a, for example, at or above a fracture pressure. For example, a thin fluid can be communicated into the rock matrix 202 a from the wellbore 201 a, and the pressure of the thin fluid in the rock matrix 202 a can create zones of intense shearing strain that induce the shear bands 203.

In some instances, the shear bands 203 are induced by plastic deformation of the rock matrix 202 a under the pressure of the thin injection fluid. For example, the deformation can be caused by material instability in the rock matrix corresponding to increase in pore pressure surrounding the wellbore. In some instances, the shear bands 203 are formed due to shear loading applied to the rock matrix 202 a by a thin fluid that has a significant leak-off rate and low viscosity in the rock matrix 202 a, in combination with the subterranean formation that restrains the rock matrix 202 a. As a result of the shear bands 203 that have been formed in the rock matrix 202 a, fluid subsequently injected into the rock matrix 202 a through the wellbore 201 a in FIG. 2A will be conducted from the wellbore 201 a primarily through the portion of the rock matrix 202 a forming the wall of the wellbore 201 a, primarily through any of the shear bands 203 intersecting the interior wall of the wellbore 201 a, or primarily through both the rock matrix and the shear bands.

In some implementations, fluid injection parameters can be controlled to achieve the conditions that cause shear bands 203 to form in the rock matrix 202 a. For example, in some cases a sufficiently high injection rate can induce some or all of the shear bands 203. In some cases, treatment adjuncts, additives or formulations can be used to effectively cause an increase in bottom hole treating pressure or change the treatment penetration profile such that the fracture system includes the entire target interval. For example, treatment adjuncts may include sand, gravel, proppant, foam, particulate diverter materials, plugging diverter materials of various forms or shapes, relative permeability modifiers, and/or others. Such adjunct materials can be included with treatment fluids to block fluid entry into and leak-off from existing fracture networks (e.g., in other zones), thus allowing subsequent injection to create new fracture networks and radial penetration of treatment through out the treatment interval.

FIG. 2B is a diagram 200 b of an example rock matrix 202 b that includes bi-wing fractures 212. The diagram 200 b is also viewed at a cross-section, with a wellbore 201 b at the center of the rock matrix 202 b. The bi-wing fractures 212 are formed by a fracture initiation at the wellbore wall and propagation of the fracture from the wellbore wall due to high stress concentration. The bi-wing fractures 212 are the dominant fractures in the rock matrix 202 b. The example bi-wing fracture shown in FIG. 2B includes two fractures radially opposite from each other. Dominant fractures having other geometries may be formed in a similar manner. Fluid injected into the rock matrix 202 b through the wellbore 201 b in FIG. 2B will be conducted from the wellbore 201 b primarily through the open space in the dominant fractures.

FIG. 2C is a diagram of an example rock matrix that includes radial shear bands. The diagram 200 c is viewed at a cross-section, with a wellbore 201 c at the center of the diagram. The example radial shear bands shown in FIG. 2C extend radially from the well bore. The shear bands 203 can be induced by pumping highly permeable fluids through the wellbore 201 c and into the rock matrix 202 c at a fluid pressure that induces discontinuities in the rock matrix 202 c, for example, at or above a fracture pressure. For example, a thin fluid can be communicated into the rock matrix 202 c from the wellbore 201 c, and the pressure of the thin fluid in the rock matrix 202 c can create zones of intense shearing strain that induce the shear bands 203. In some implementations, radial shear bands are formed during an initial phase of shear band formation in the rock matrix 202 c.

In some instances, the shear bands 203 are induced by plastic deformation of the rock matrix 202 c under the pressure of the thin injection fluid. For example, the deformation can be caused by material instability in the rock matrix corresponding to increase in pore pressure surrounding the wellbore. In some instances, the shear bands 203 are formed due to shear loading applied to the rock matrix 202 c by a thin fluid that has a significant leak-off rate and low viscosity in the rock matrix 202 c, in combination with the subterranean formation that restrains the rock matrix 202 c. In some instances, the induced shear bands may initially form a radial fracture pattern from the wellbore 201 c. In some instances, the induced shear bands may initially form a different type of fracture pattern. As a result of the shear bands 203 that have been formed in the rock matrix 202 c, fluid subsequently injected into the rock matrix 202 c through the wellbore 201 c in FIG. 2C will be conducted from the wellbore 201 c primarily through the portion of the rock matrix 202 c forming the wall of the wellbore 201 c, primarily through any of the shear bands 203 intersecting the interior wall of the wellbore 201 c, or primarily through both the rock matrix and the shear bands.

As shown in FIGS. 2A and 2B, different forms of rock discontinuities are created by different loading conditions and different properties of treatment fluids. The shear bands 203 in FIG. 2A can be formed, for example, in a rock matrix 202 a that has softer mechanical properties and may also lack a dominant stress concentration. In addition, the treatment fluids have permeability high enough to allow significant leak-off such that a complex fracture system can be created near the wellbore 201 a. The treatment fluids can then leak out of the fracture system into the rock matrix formation 202 a and effectively create a radial penetration of the treatment around the wellbore 201 a. The thin, low viscosity treatment fluids can be pumped at rates and pressures sufficient to cause multiple or complex or shear failure mode fracture networks emanating from the wellbore 201 a to the rock matrix 202 a. In this manner, the treatment fluids can generate a system of smaller and irregular discontinuities in the rock matrix 202 a near the wellbore, and the network of discontinuities can communicate production fluids between the wellbore and the rock matrix 202 a. By contrast, in FIG. 2B the bi-wing fracture 212 is created in a traditional manner with low permeability fluids pumped at a rate that causes an opening mode of fracture.

FIG. 3 is a diagram of an example well system 300 for applying a chemical treatment to a subterranean formation 101. The example well system 300 can include the features of the example well system 100 in FIG. 1. The example working string 104 shown in FIG. 3 includes three flow control devices 122 a, 122 b, and 122 c. A working string may include a different number of flow control devices. Each of the flow control devices 122 a, 122 b, 122 c controls the flow of injection fluid 308 into the rock matrix 106 about the wellbore 103. Packers 124 reside in the wellbore 103 in the annulus between the working string 104 and the interior wall of the wellbore 103 (or between the working string 104 and the casing, where the wellbore 103 is cased). The packers 124 isolate longitudinal sections of the annulus. Each of the longitudinal sections receive the fluid injected from one of the flow control devices 122 a, 122 b, 122 c. The packers 124 may include mechanical packers, fluid inflatable packers, sand packers, swellable packers, chemical isolation implementations and/or other types of packers.

The injection fluid 308 can have the mechanical properties of a Newtonian fluid, for example, a fluid whose stress at any point is linearly proportional to its strain rate at that point, where the constant of proportionality is the viscosity of the fluid. The injection fluid 308 can be a thin fluid, for example, that contains substantially no solids and does not form filter cakes in the wellbore. The injection fluid 308 can be an incompressible fluid, a multiphase fluid, and/or a composition of multiple different types of fluids. The injection fluid 308 can substantially uniformly permeate the rock matrix 106 about the wellbore 103 and create shear discontinuities in the rock matrix 106.

In some implementations of the example system 300, each of the flow control devices 122 a, 122 b, 122 c can be selectively opened, selectively closed, or otherwise reconfigured, for example, by well intervention, by pressure signals or electromagnetic signals propagated from the surface, and/or by another technique. In some implementations, the flow control devices 122 a, 122 b, 122 c can be simultaneously opened or closed. In some instances, the injection fluid 308 is communicated through the flow control devices 122 a, 122 b and 122 c into the rock matrix 106 at a pressure that forms shear bands 330 in the rock matrix. The injection fluid 308 can be communicated simultaneously through two or more of the flow control devices 122 a, 122 b, 122 c, or the injection fluid 308 can be communicated through each of the flow control devices 122 a, 122 b, 122 c at different times. As such, the shear bands 330 can be formed throughout the rock matrix 106 concurrently, over multiple time intervals, or in another manner.

The shear bands 330 can be formed substantially uniformly about the wellbore 103. For example, the shear bands 330 can be distributed through the rock matrix 106 such that the rock matrix 106 does not have substantial spatial variations in permeability that would create preferential flow through certain regions of the rock matrix 106. As such, in some instances, the shear bands 330 permit substantially uniform flow of a chemical treatment fluid from the wellbore 103 into the rock matrix 106 about the wellbore 103. In some instances, the shear bands 330 are uniform over a targeted section of the rock matrix 106. For example, the shear bands may be uniform over a longitudinal section, an azimuthal section, and/or a radial section about the wellbore.

The fluid supply 118 can supply a single fluid or it can supply multiple different fluids. In some implementations, the injection fluid 308 that forms the shear bands 330 is also the chemical treatment fluid. For example, the injection fluid 308 that forms the shear bands 330 can be the treatment fluid for an acid stimulation treatment, a scale inhibitor treatment, a formation stabilization treatment, a consolidation treatment, or another type of chemical treatment fluid. In some implementations, the chemical treatment fluid is a separate fluid that is injected after the injection fluid 308 that forms the shear bands 330. For example, after the injection fluid 308 has been injected to form the shear bands 330, the treatment fluid for an acid stimulation treatment, a scale inhibitor treatment, a formation stabilization treatment, a consolidation treatment, or another type of chemical treatment fluid can be injected.

FIGS. 4A, 4B, and 4C are diagrams of an example well system 400 for applying a chemical treatment to multiple intervals of a subterranean formation 101. The example well system 400 shown in FIGS. 4A, 4B, and 4C can include the features of the example well system 300 in FIG. 3. The fluid supply 118 of FIGS. 4A, 4B, and 4C includes two different fluids, and may include additional fluids that are not illustrated in the figures. In particular, the fluid supply 118 includes a thin injection fluid 119 a that can be injected into the rock matrix 106 to form shear bands in the rock matrix. The fluid supply 118 also includes an adjunct-laden injection fluid 119 b that can be injected into the rock matrix 106 to plug an interval of the rock matrix 106.

As shown in FIGS. 4A, 4B, and 4C, the rock matrix 106 includes multiple intervals 116 a, 116 b, 116 c. Each of the intervals 116 a, 116 b, and 116 c is adjacent to one of the longitudinal sections of the wellbore 103 defined by the packers 124. As such, the intervals 116 a, 116 b, and 116 c are identified by locations of the packers 124 in the annulus of the wellbore 103. Intervals may be identified by additional or different types of structures, or in a different manner. In the example shown, each of the flow control devices 122 a, 122 b, and 122 c is operable to inject fluid into one of the intervals 116 a, 116 b, and 116 c. For example, due to the fluid isolation provided by the packers 124, the flow control device 122 a injects fluid into the interval 116 a, the flow control device 122 b injects fluid into the interval 116 b, and the flow control device 122 c injects fluid into the interval 116 c. In some instances, more than one flow control device can be used to inject fluid into each of the intervals.

Each of the individual intervals 116 a, 116 b, 116 c can be treated in sequence, or some or all of the intervals 116 a, 116 b, 116 c can be treated simultaneously. In the example process shown by FIGS. 4A, 4B, and 4C, the first interval 116 a is treated, then the second interval 116 b is treated, and the third interval 116 c can be treated subsequently. Generally, the intervals 116 a, 116 b, 116 c can be treated in any order, in a cyclical fashion, or in another manner.

In some implementations, a more uniform treatment of the rock matrix 106 can be achieved by applying the chemical treatment to individual intervals of the rock matrix 106. For example, to the extent that there are variations in permeability among the intervals 116 a, 116 b, 116 c, the permeability within interval can be substantially uniform. As such, if the one of the intervals has a higher permeability than the other two, preferential treatment of the high permeability interval may be reduced or avoided by isolating the high permeability interval from the others.

The operations shown in FIGS. 4A, 4B, and 4C can, in some implementations, achieve more uniform placement of treatment fluid across the length of the rock matrix 106. For example, the system 400 may achieve more uniform radial penetration for sand consolidation treatments to give more reliable recovery, higher production rates without sand, and improved longevity of sand free production in the treated formation. In some other examples, the system 400 may achieve more uniform acid coverage, penetration and stimulation of a target interval in an acid stimulation treatment, and more uniform coverage to assure all parts of the zone receive the inhibitor in a scale inhibitor treatment.

As shown in FIG. 4A, flow control device 122 a is open while the flow control devices 122 b and 122 c are closed. The thin injection fluid 119 a is pumped into the interval 116 a through the flow control device 122 a. The thin injection fluid 119 a in the first interval 116 a of the rock matrix 106 forms shear bands 430 a in the first interval 116 a. A chemical treatment fluid can be applied to the first interval. For example, the thin injection fluid 119 a or another fluid can be the chemical treatment fluid that treats the first interval 116 a.

As shown in FIG. 4B, after the chemical treatment has been applied to the first interval 116 a, the adjunct-laden fluid 119 b can be injected into the first interval 116 a. The adjunct-laden injection fluid 119 b can be communicated into all or part of the first interval 116 a through the first flow control device 122 a. The adjunct-laden fluid plugs the first interval 116 a to reduce the flow of fluids into the first interval 116 a when subsequent intervals (e.g., 116 b, 116 c) are treated.

The treatment process can then continue to the next interval as shown in FIG. 4C. The operations described with respect to FIGS. 4A and 4B can be repeated for the second interval 116 b, and subsequently for the third interval 116 c. For example, as shown in FIG. 4C, the flow control devices 122 a and 122 c are closed and the flow control device 122 b is open. The thin injection fluid 119 a is communicated into the second interval 116 b and forms shear bands 430 b in the interval 116 b. Subsequently, after the chemical treatment has been applied to the second interval 116 b, the adjunct-laden injection fluid 119 b can be applied to the second interval 116 b. Similarly, the flow control devices 122 a and 122 b can be closed and the flow control device 122 c can be opened. The thin injection fluid 119 a can be communicated into the third interval 116 c and form shear bands in the third interval 116 c. Subsequently, after the chemical treatment has been applied to the third interval 116 c, the adjunct-laden injection fluid 119 b can be applied to the third interval 116 c. Additional intervals (not shown) can be treated by the same technique.

FIG. 5 is a flow chart showing an example process 500 for performing a chemical treatment of a rock matrix. All or part of the example process 500 may be implemented using features and attributes of the example well systems shown in FIGS. 1, 3, 4A, 4B, and 4C. In some cases, the process 500 may be implemented by a different type of system. Aspects of the example process 500 may be performed in a single-well system, a multi-well system, a well system that includes multiple interconnected wellbores, and/or in another type of well system, which may include any suitable wellbore orientations. In some instances, the process 500 is used for applying a chemical treatment to a rock matrix prior to producing resources through the rock matrix or fracturing the rock matrix. The process 500, including individual operations of the process 500 and/or groups of the operations, may be iterated or repeated, and/or they may be performed in connection with another process. In some cases, the process 500 may include the same, additional, fewer, and/or different operations performed in the same or a different order.

At 502, a first interval in a subterranean formation is identified. The subterranean formation can include a soft rock formation having low stiffness, for example, a rock formation that includes rock materials having a Young's Modulus value less than two million. Examples of soft rock formations include shale, coal, and certain types of geologically young formations (e.g., Miocene and Pliocene period formations, and others). In some cases, the material in such rock formations can include brittle rock having low elasticity.

The interval is an interval along a wellbore in the subterranean formation. The interval includes the rock formation around a longitudinal section the wellbore. The longitudinal section can be any suitable length. The longitudinal section may include a section of a vertical, slant, curved, or horizontal wellbore, including a toe, heel, or intermediate section in the horizontal wellbore. The interval may be isolated by seals, packers, or other types of isolators installed in the wellbore.

The interval can be identified for receiving a chemical treatment. The chemical treatment to be applied to the interval can include any type of chemical treatment to be applied uniformly in the interval. Example chemical treatments include acid stimulation treatments, formation stabilization treatments, consolidation treatments, scale inhibitor treatments, treatments that remove buildup of paraffin, asphaltene, or another substance from the rock material, heat transfer treatments, water flood treatments, and others. The chemical treatment can be a radial treatment to be placed radially about the wellbore over a radial depth into the rock formation from the wellbore wall.

At 504, fluid is communicated into the first interval to induce shear bands in the interval. The fluid can be communicated to induce shear bands at any stage of a treatment. For example, shear bands can be induced during a first injection stage, or any subsequent injection stage. The fluid can be part of the chemical treatment and/or the fluid can be injected to prepare the interval to later receive the chemical treatment. As such, the fluid that induces the shear bands can be or can contain the chemical treatment fluid, or the fluid that induces the shear bands can be a separate fluid from the chemical treatment fluid. The fluid can have mechanical properties of a Newtonian fluid, for example, a fluid whose stress at any point is linearly proportional to its strain rate at that point, where the constant of proportionality is the viscosity of the fluid. The fluid can be a thin fluid, for example, that contains substantially no solids and does not form filter cakes in the wellbore. The fluid can be an incompressible fluid, a multiphase fluid, and/or a composition of multiple different types of fluids.

The fluid can be received in the wellbore from a fluid supply system at the surface of the well system, and the fluid can be communicated through the wellbore by a conduit system in the wellbore. For example, the fluid can flow through any type work string, tubing, or casing in the wellbore. The fluid is communicated into the interval from the wellbore at 504, for example, through perforations in the wellbore casing, through a port in a production string (e.g., an inflow control device, a valve, or another type of device), or through another type of port system in the wellbore.

The fluid may be communicated into the rock matrix at 504 at or above a fracture pressure without causing dominant fractures to propagate from the wellbore wall. As such, the fluid can be communicated into the rock matrix without forming conventional bi-wing fractures or similar discontinuities in the rock matrix. For example, by using thin fluids that have a low viscosity and/or a high leak-off rate in the rock matrix, the fluid can be injected above a fracture pressure without initiating or propagating a dominant open fracture at the wellbore wall. Because dominant open fractures are not formed at the wellbore wall, fluid can be conducted from the wellbore primarily by the rock matrix itself (i.e., a portion of the rock matrix that forms a wall of the wellbore) and/or primarily by shear bands in the rock matrix (i.e., shear bands that intersect the wall of the wellbore).

The shear bands are formed in the interval substantially uniformly about the wellbore. For example, the distribution of the induced shear bands can be substantially uniform over a full range of azimuthal directions about the wellbore, over the full longitudinal length of the interval, and/or over a finite depth into the formation from the wellbore wall. The full range of azimuthal directions can be a full 360 degrees about the wellbore, or a smaller range when appropriate. In some instances, the full longitudinal length of the interval is the distance between packers that isolate the interval from a neighboring interval. The finite depth into the formation from the wellbore can be a depth of several centimeters to several meters or more.

The uniformity of the shear bands in the interval results in a higher permeability of the rock matrix that is substantially uniform over the interval. For example, the increased permeability may be substantially uniform over a full range of azimuthal directions about the wellbore, over the full longitudinal length of the interval, and/or over a finite depth into the formation from the wellbore wall. In such cases, the fluid is communicated substantially uniformly into the rock matrix as the fluid is conducted through the shear bands in the interval. Thus, in some implementations, the shear bands improve the uniformity, range, and/or speed of fluid distribution in the interval.

In some implementations of the process 500, the first interval is plugged at 506 after the shear bands are formed in the interval. For example, the first interval may be plugged by communicating a proppant-laden fluid into the first interval. The proppant-laden fluid contains proppant material (i.e., solids) that plug open volumes in the interval. The interval may be plugged in a different manner, for example, by closing a port of a production string (e.g., by reconfiguring an inflow control device, a valve, or another device), by use of a relative permeability modifier, or by plugging perforations in a well casing. Plugging the interval prevents or substantially reduce the rate at which fluid can be communicated into the interval from the wellbore. As such, when subsequent intervals are treated, the plugging material can prevent or reduce the communication of fluids into the first interval (or any intervals that have been plugged).

After the first interval is plugged, a next interval of the subterranean formation is identified at 508. Fluid is then communicated into the next interval to induce shear bands in the next interval (504). The operations 504, 506, and 508 may be iterated for any number of intervals along the wellbore. In some implementations of the process 500, only a single interval is used. For example, the first interval may be the entire target region for the chemical treatment, or the first interval may be the only interval available. As such, in some implementations no additional intervals are identified and/or the first interval is not plugged.

At 510, additional fluid may be communicated into the first interval and/or into one or more other intervals in the subterranean formation. The additional fluid applied at 510 may be the same or a different fluid than was used to induce the shear bands at 504. The additional fluid communicated into the interval(s) at 510 can be part of a different chemical treatment than the fluid that was used to induce the shear bands at 504. The additional fluid communicated into the interval(s) at 510 can be part of the same chemical treatment that was applied at 504. Due to the presence of the shear bands, the additional fluid is communicated substantially uniformly into the rock matrix within each interval as the fluid is conducted through the shear bands in the interval(s). Thus, in some implementations, the shear bands improve the uniformity, range, and/or speed of distribution of the additional fluid in the interval. The additional fluid can be conducted from the wellbore primarily by the rock matrix itself and/or primarily by shear bands in the rock matrix intersecting the wall of the wellbore.

In some implementations of the process 500, the additional fluid is communicated into the first interval prior to inducing shear bands in any other interval. For example, after inducing the shear bands in the first interval at 504 and communicating additional fluid into the first interval at 510, the first interval may be plugged at 506, the next interval may be identified at 508, and one or more of the operations (504, 510, 506, 508) may be iterated for subsequent intervals.

In some implementations of the process 500, the additional fluid is communicated into the first interval after inducing the shear bands in the other intervals. For example, after inducing shear bands in multiple intervals, any intervals that have been plugged can be unplugged to allow communication of the additional fluid into the intervals. An interval may be unplugged, for example, by dissolving or otherwise removing the proppant or other diverter materials that were used to plug the interval. An interval may be unplugged by opening a port of a production string (e.g., by reconfiguring an inflow control device, a valve, or another device) or by dissolving or otherwise removing a plug from perforations in a well casing. As such, the additional fluid may be communicated into multiple different intervals simultaneously, sequentially, or in a different manner.

A number of embodiments have been described. Nevertheless, it will be understood that various modifications may be made without departing from the spirit and scope of the invention. Accordingly, other embodiments are within the scope of the following claims. 

1. A method of performing a chemical treatment of a rock matrix, the method comprising: receiving an injection fluid in a wellbore defined in a subterranean formation, the subterranean formation comprising a rock matrix about the wellbore; inducing shear bands in the rock matrix about the wellbore by communicating the injection fluid from the wellbore into the rock matrix about the wellbore; and communicating a chemical treatment fluid through the shear bands and into the rock matrix about the wellbore, the chemical treatment fluid conducted from the wellbore primarily by at least one of a portion of the rock matrix forming a wall of the wellbore or a subset of the shear bands intersecting the wall.
 2. The method of claim 1, a leak-off rate of the injection fluid in the rock matrix prevents initiation of a dominant fracture at the wellbore wall.
 3. The method of claim 1, wherein the injection fluid comprises the chemical treatment fluid.
 4. The method of claim 1, wherein the wellbore comprises a wellbore casing, and fluids communicated from the wellbore into the rock matrix are communicated through perforations in the wellbore casing.
 5. The method of claim 1, wherein the wellbore comprises an open hole wellbore.
 6. The method of claim 1, further comprising: receiving the chemical treatment fluid in the wellbore after communicating the injection fluid into the rock matrix; and communicating the chemical treatment fluid from the wellbore through the shear bands after communicating the injection fluid into the rock matrix.
 7. The method of claim 1, wherein inducing shear bands comprises inducing the shear bands in the rock matrix substantially uniformly over a range of azimuthal directions about the wellbore.
 8. The method of claim 7, wherein communicating a chemical treatment fluid into the rock matrix comprises communicating the chemical treatment fluid into the rock matrix substantially uniformly over the range of azimuthal directions about the wellbore.
 9. The method of claim 1, wherein inducing shear bands comprises inducing the shear bands in the rock matrix substantially uniformly about a longitudinal section of the wellbore.
 10. The method of claim 9, wherein communicating a chemical treatment fluid into the rock matrix comprises communicating the chemical treatment fluid into the rock matrix substantially uniformly about the longitudinal section of the wellbore
 11. The method of claim 1, wherein inducing shear bands comprises inducing the shear bands in the rock matrix substantially uniformly over a radial distance about the wellbore.
 12. The method of claim 11, wherein communicating a chemical treatment fluid into the rock matrix comprises communicating the chemical treatment fluid into the rock matrix substantially uniformly over the radial distance about the wellbore
 13. The method of claim 1, wherein inducing shear bands in the rock matrix comprises inducing shear bands in a first interval of the rock matrix, the method further comprising: inducing additional shear bands in multiple additional intervals of the rock matrix by communicating the injection fluid from the wellbore into the additional intervals of the rock matrix about the wellbore, wherein the injection fluid is communicated into each of the intervals at different time periods; and communicating the chemical treatment fluid through the additional shear bands and into additional intervals of the rock matrix.
 14. The method of claim 1, wherein the injection fluid comprises a thin injection fluid containing substantially no solids, and wherein the thin injection fluid forms substantially no filter cakes.
 15. The method of claim 1, wherein the rock matrix comprises a soft rock formation having a Young's Modulus less than two million.
 16. The method of claim 1, wherein the chemical treatment comprises at least one of: an acid stimulation treatment; a solvent treatment; a formation stabilization treatment; a consolidation treatment; or a scale inhibitor treatment.
 17. A chemical treatment method for treating a rock matrix about a subterranean wellbore, the chemical treatment method comprising: communicating a first fluid from the wellbore into an interval of the rock matrix about the wellbore at a pressure that forms shear bands in the interval about the wellbore; and communicating a chemical treatment fluid substantially uniformly into the interval of the rock matrix about the wellbore by conducting the chemical treatment fluid through the shear bands in the interval, the chemical treatment fluid conducted from the wellbore primarily by at least one of a portion of the rock matrix forming a wall of the wellbore or a subset of the shear bands intersecting the wall.
 18. The method of claim 17, a leak-off rate of the first fluid in the rock matrix prevents initiation of a dominant fracture at the wellbore wall.
 19. The method of claim 17, wherein the first fluid is the chemical treatment fluid.
 20. The method of claim 17, wherein inducing the shear bands in the rock matrix increases a permeability of the rock matrix.
 21. The method of claim 17, wherein the first fluid and the chemical treatment fluid are two different fluids and the chemical treatment fluid is communicated into the interval after the first fluid is communicated into the interval.
 22. The method of claim 21, further comprising communicating additional fluids into the rock matrix.
 23. The method of claim 17, wherein the first fluid comprises a thin injection fluid containing substantially no solids, and wherein the thin injection fluid forms substantially no filter cakes, and wherein the rock matrix comprises a soft rock formation having a Young's Modulus less than two million.
 24. The method of claim 17, the interval comprising a first interval, the method further comprising: injecting a diverter-laden fluid into the first interval; communicating the first fluid from the wellbore into a second, different interval of the rock matrix about the wellbore at a pressure that forms shear bands in the second interval about the wellbore; and communicating the chemical treatment fluid substantially uniformly into the second interval of the rock matrix about the wellbore by conducting the chemical treatment fluid through the shear bands in the second interval.
 25. The method of claim 24 where the diverter comprises at least one of sand, a proppant, a plugging material, an emulsion, foam, or a relative permeability modifier.
 26. A chemical treatment system for applying a chemical treatment to a rock matrix, the system comprising: a fluid supply system comprising a thin injection fluid and a chemical treatment fluid; a conduit system in a wellbore in a subterranean formation, the conduit system in fluid communication with the fluid supply system, the subterranean formation comprising a rock matrix; and a port system in the wellbore and in fluid communication with the conduit system, the port system operable to receive the thin injection fluid and the chemical treatment fluid from the conduit system, to communicate the thin injection fluid into the rock matrix under a condition that induces shear bands in the rock matrix about the wellbore, and to communicate the chemical treatment fluid into the rock matrix primarily through at least one of the rock matrix at a wall of the wellbore or a subset of the shear bands intersecting the wall.
 27. The system of claim 26, wherein the fluid supply system resides at a well system surface, and wherein the fluid supply system comprises a single fluid composition that is both the thin injection fluid and the chemical treatment fluid.
 28. The system of claim 26, wherein the fluid supply system resides at a well system surface, and wherein the fluid supply system comprises a first fluid composition that is the thin injection fluid and second, different fluid composition that is the chemical treatment fluid.
 29. The system of claim 26, wherein the conduit system comprises one or more conduits in a production string, and wherein the port system comprises a plurality of inflow control devices in the production string.
 30. The system of claim 26, wherein the conduit system comprises one or more conduits within a wellbore casing, and wherein the port system comprises a plurality of perforations in the wellbore casing.
 31. The system of claim 26, wherein the condition comprises at least one of an injection pressure condition or an injection flow rate condition. 